It is common practice in completing oil and gas wells to set a string of pipe, known as casing, in the well and use a cement sheath around the outside of the casing to isolate the various formations penetrated by the well. To establish fluid communication between the hydrocarbon-bearing formations and the interior of the casing, the casing and cement sheath are perforated. At various times during the life of the well, it may be desirable to increase the production rate of hydrocarbons using appropriate treating or stimulation fluids such as acids, solvents or suffactants. If only a short, single pay zone in the well has been perforated, the treating fluid will flow into the pay zone where it is needed. As the length of the perforated pay zone or the number of perforated pay zones increases, the placement of the treating or stimulation fluid in the regions of the pay zones where it is needed becomes more difficult. For instance, the strata having the highest permeability will most likely consume the major portion of a given stimulation treatment, leaving the least permeable strata virtually untreated.
Various techniques have been developed to redirect stimulation fluids towards lower permeability zones to ensure that damaged formations are sufficiently exposed to these fluids. One such technique for achieving diversion involves the use of downhole equipment such as packers. Although these devices can be effective, they are quite expensive due to the involvement of associated workover equipment required during the tubing-packer manipulations. Additionally, mechanical reliability tends to decrease as the depth of the well increases. As a result, considerable effort has been devoted to the development of alternative diverting methods for cased and perforated wells.
One such alternative is to redirect stimulation fluids toward lower permeability zones by using ball sealers to temporarily block perforations that exist across higher permeability zones. Generally, the ball sealers are pumped into the wellbore along with the formation treating fluid and are carried down the wellbore and onto the perforations by the flow of the fluid through the perforations into the formation. The balls seat upon the perforations receiving the majority of fluid flow and, once seated, are held there by the pressure differential across the perforations. The ball sealers are injected at the surface and transported by the treating fluid. Other than a ball injector and possibly a ball catcher, no special or additional treating equipment is required. Major advantages of utilizing ball sealers as a diverting agent include ease of use, positive shutoff, no involvement with the formation, and low risk of incurring damage to the well. As described further below, ball sealers are typically designed to be chemically inert in the environment to which they are exposed; to effectively seal, yet not extrude into the perforations; and to release from the perforations when the pressure differential into the formation is relieved.
The oil and gas industry began using ball sealers as a diverting agent around 1956. Since that time the majority of wells have been completed at depths less than 15,000 ft, and as a result most commercially available ball sealers are designed to perform at temperatures and at pressures commonly associated with wells of depths less than 15,000 ft. In most cases these wells will have temperatures less than 250.degree. F. and maximum bottomhole pressures not exceeding 10,000 to 15,000 psi during a workover. In recent years, however, technological developments have enabled the oil and gas industry to drill and complete wells at depths exceeding 15,000 ft., which will often have higher temperatures and pressures. For example, at a depth of around 25,000 ft., wellbore temperatures can exceed 400.degree. F., with bottomhole pressures approaching 20,000 psi during a workover. In addition to the high temperatures and pressures, wells completed at these depths often produce fluids like carbon dioxide (CO.sub.2) or hydrogen sulfide (H.sub.2 S), and the stimulation fluid used may be a solvent like hydrochloric acid (HCl). Thus, conducting a workover using ball sealers in deep, hostile environment wells requires ball sealers capable of withstanding high pressures and temperatures while exposed to gases and solvents. The ball sealers must also resist changes in density to ensure satisfactory seating efficiencies result during a workover.
Most commercially available ball sealers will have a solid, rigid core (which resists extrusion into or through a perforation in the formation) and an outer coveting sufficiently compliant to seal, or significantly seal, the perforation. The ball sealers should not be able to penetrate the formation since penetration could result in permanent damage to the flow characteristics of the well. Commercially available ball sealers are typically spherical with a hard, solid core made from nylon, phenolic, syntactic foam, or aluminum. The solid cores may be covered with rubber to protect them from solvents and to enhance their sealing capabilities. Ball sealer diameters typically range from 5/8-in to 11/4 in, with specific gravities ranging from 0.8 to 1.9. With the exception of syntactic foam cores, most of the rubber-coated balls are designed to withstand hydrostatic pressures below 10,000 psi at temperatures below 200.degree. F. Specific gravities of rubber-coated balls typically range from 0.9 to 1.4. Ball sealers with syntactic foam cores are capable of withstanding hydrostatic pressures up to 15,000 psi at temperatures up to 250.degree. F., and have specific gravities ranging from 0.9 to 1.1.
These ball sealers will, however, begin to degrade when temperatures or pressures exceed the design limits. Degradation can also occur when exposing ball sealers to fluids like HCl, CO.sub.2, or H.sub.2 S. Additionally, in the case of rubber coated ball sealers, the perforation can actually cut the rubber coating in the area of the pressure seal. Once the ball sealer loses its structural integrity, the unattached rubber is free to lodge permanently in the perforation which can reduce the flow capacity of the perforation and may permanently damage the well. The cut rubber coating will also result in exposure of the ball core material to the stimulation fluid, possibly resulting in dissolution of the core material. The capability of a ball sealer to block a perforation will diminish notably if degradation results in excessive ball deformation or in a breakdown of ball material. A ball sealer must remain essentially undeformed and intact under high pressures and temperatures to effectively block a perforation during a workover. Thus, material strength and environmental resistance are important aspects of ball sealer design.
Another important aspect of ball sealer design is density (or specific gravity). Past research and field studies indicate that the number of ball sealers that will seat onto perforations located inside a well (seating efficiency) depends on several factors, including the relative density of the ball sealer and the wellbore fluid. Erbstoesser (see "Improved Ball Sealer Diversion," SPE Paper 8401, 1979) observed that maximum seating efficiencies occurred when the ball density was 0.02 gm/cc less than the workover fluid density which typically ranges from 0.8 to 1.3 gm/cc. Thus, most workovers will require a low-density ball sealer in order to enhance seating efficiencies. Ball sealer density should also remain essentially constant to minimize changes between the relative density of the ball sealer and the wellbore fluid during a workover. There are various materials having high temperature and high pressure resistances. However, the problem with using these materials for a solid core ball sealer design is that these materials will typically have a high density as compared to common treating fluids. As a result, this higher density can prevent current commercial, solid core ball sealer designs made of such high strength materials from seating against the perforations.
Another potential problem with commercial ball sealers is quality control during ball manufacturing. The densities of ball sealers delivered for use during a workover will often vary notably from specified values. The lack of proper quality control when forming the solid core material, coupled with irregularities when applying the rubber coating, can cause variations in the overall ball density, and such variations can notably affect seating efficiencies during a workover. Current ball sealer designs do not allow for adjustments to be made to the ball sealer density prior to initiation of a workover. Thus, because of inventory costs, only a select range of ball sealer densities are typically available for immediate use.
To summarize, deeper drilling has demanded stimulation jobs that are conducted under conditions that exceed the current temperature, pressure, and well-condition limitations of available low density ball sealers. Available low density ball sealers are not designed to withstand temperatures over 200.degree.-250.degree. F., hydrostatic pressures over 10,000-15,000 psi, or differential pressures over 1,500 psi (at these high temperatures and hydrostatic pressures). They are currently unable to perform effectively when exposed to hostile well environments: They deform excessively when exposed to the high temperatures and high bottomhole pressures often associated with deeper wells, particularly during long workovers or when exposed to solvents. Furthermore, those commercial ball sealers designed to withstand higher pressures or temperatures (e.g. rubber-covered, high strength, solid phenolic core) will have densities higher than the stimulation fluids used during the workover. Thus, the ball sealers will either not seat at all or seating efficiencies will decrease. The ability of commercial ball sealers to perform satisfactorily will decrease notably as temperatures begin to exceed 200.degree. F. (93.degree. C.). Ball sealer performance is limited further when hydrostatic pressures exceed 10,000 psi or when differential pressures across the perforations exceed 1,500 psi at high temperatures and pressures. Such conditions are common during workovers in deep, hostile environment wells. For the foregoing reasons, a need exists for improved low density ball sealers which function properly in such hot, hostile environment wells, especially in the presence of acidic fluids.